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WO2018102199A1 - Procédé de prédiction de tension interfaciale d'huile brute dans des conditions de réservoir à partir de mesures d'huile morte - Google Patents

Procédé de prédiction de tension interfaciale d'huile brute dans des conditions de réservoir à partir de mesures d'huile morte Download PDF

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Publication number
WO2018102199A1
WO2018102199A1 PCT/US2017/062758 US2017062758W WO2018102199A1 WO 2018102199 A1 WO2018102199 A1 WO 2018102199A1 US 2017062758 W US2017062758 W US 2017062758W WO 2018102199 A1 WO2018102199 A1 WO 2018102199A1
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WO
WIPO (PCT)
Prior art keywords
oil
ift
fluid
density
live
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2017/062758
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English (en)
Inventor
Mikhail Stukan
Bastian SAUERER
Wael Abdallah
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Technology Corp
Original Assignee
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Technology Corp
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Filing date
Publication date
Application filed by Schlumberger Canada Ltd, Services Petroliers Schlumberger SA, Schlumberger Technology BV, Schlumberger Technology Corp filed Critical Schlumberger Canada Ltd
Publication of WO2018102199A1 publication Critical patent/WO2018102199A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V20/00—Geomodelling in general
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E21B47/07—Temperature
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
    • E21B49/087—Well testing, e.g. testing for reservoir productivity or formation parameters
    • E21B49/0875—Well testing, e.g. testing for reservoir productivity or formation parameters determining specific fluid parameters
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N13/00—Investigating surface or boundary effects, e.g. wetting power; Investigating diffusion effects; Analysing materials by determining surface, boundary, or diffusion effects
    • G01N13/02—Investigating surface tension of liquids
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N33/00—Investigating or analysing materials by specific methods not covered by groups G01N1/00 - G01N31/00
    • G01N33/26—Oils; Viscous liquids; Paints; Inks
    • G01N33/28—Oils, i.e. hydrocarbon liquids
    • G01N33/2823—Raw oil, drilling fluid or polyphasic mixtures
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N9/00—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity
    • G01N9/36—Analysing materials by measuring the density or specific gravity, e.g. determining quantity of moisture
    • G—PHYSICS
    • G06—COMPUTING OR CALCULATING; COUNTING
    • G06F—ELECTRIC DIGITAL DATA PROCESSING
    • G06F17/00—Digital computing or data processing equipment or methods, specially adapted for specific functions
    • G06F17/10—Complex mathematical operations
    • G06F17/11—Complex mathematical operations for solving equations, e.g. nonlinear equations, general mathematical optimization problems
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
    • E21B49/087—Well testing, e.g. testing for reservoir productivity or formation parameters
    • E21B49/088—Well testing, e.g. testing for reservoir productivity or formation parameters combined with sampling
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N13/00—Investigating surface or boundary effects, e.g. wetting power; Investigating diffusion effects; Analysing materials by determining surface, boundary, or diffusion effects
    • G01N13/02—Investigating surface tension of liquids
    • G01N2013/0283—Investigating surface tension of liquids methods of calculating surface tension
    • G—PHYSICS
    • G06—COMPUTING OR CALCULATING; COUNTING
    • G06F—ELECTRIC DIGITAL DATA PROCESSING
    • G06F30/00—Computer-aided design [CAD]
    • G06F30/20—Design optimisation, verification or simulation

Definitions

  • the rate of oil recovery from hydrocarbon reservoirs is governed by the interplay of viscous and capillary forces that determine the fluid transport in porous media.
  • Surface active constituents of reservoir fluids may also accumulate at interfaces between fluid phases, such as an oil-brine interface, and phase boundaries between fluids and solids, such as an oil-rock interface, which can change interfacial properties and fluid flow characteristics. Changes at the interphase boundaries also affect the interfacial tension (TFT) and surface wettability.
  • TFT interfacial tension
  • IFT interfacial tension
  • IFT interfacial tension
  • reservoir rock wettability is an important factor. The results of IFT measurements depend on temperature, pressure, and fluid composition of a potential hydrocarbon source under reservoir conditions. However, determining IFT under reservoir conditions currently requires isolating and maintaining downhole samples at reservoir conditions, which can increase well down time and overall costs.
  • embodiments of the present disclosure are directed to methods that include measuring an interfacial tension (IFT) for a dead oil sample prepared from a fluid within an interval of a formation; calculating a gas: oil ratio for the fluid within the interval of a formation at a specified temperature and pressure; calculating a live oil density for the fluid within the interval of a formation for the specified temperature and pressure and converting the IFT for the dead oil sample to a corrected IFT measurement for a live oil within the interval of the formation from the calculated gas: oil ratio and the calculated density.
  • IFT interfacial tension
  • embodiments of the present disclosure are directed to methods that include measuring an interfacial tension (IFT) for a dead oil sample prepared from a fluid within an interval of a formation; calculating a gas: oil ratio for the fluid within the interval of a formation; calculating a live oil density for the fluid within the interval of a formation; constructing a depletion path for the dead oil sample from one or more isobars and one or more isotherms; and converting the IFT for the dead oil sample to a corrected IFT measurement from the calculated gas:oil ratio and the calculated live oil density for a live oil within the interval of the formation.
  • IFT interfacial tension
  • FIG. 1 is a graphical representation depicting a phase diagram of a crude oil sample showing two pathways from live to dead stages in accordance with an embodiment of the present disclosure
  • FIG. 2 is a graphical representation depicting a phase diagram of a crude oil sample with a superimposed depletion path in accordance with an embodiment of the present disclosure
  • FIG. 3 is a work flow diagram of a method in accordance with an embodiment of the present disclosure.
  • FIG. 4 is a schematic depicting a computer system in accordance with embodiments of the present disclosure.
  • This disclosure relates generally to methods of analyzing formation fluid and gas compositions.
  • data obtained from dead oil IFT measurements and empirical relationships may be used to determine the interfacial tension (IFT) of a hydrocarbon reserve under reservoir conditions.
  • Methods in accordance with the present disclosure may also be used to derive a "correction factor," a set of correction rules that may be used to convert the results of dead oil IFT measurements to a corresponding live oil IFT value.
  • the correction factor may be used to convert the results of dead oil IFT measurements to an IFT value for the oil at any point along a defined depletion path.
  • IFT affects the relative permeability of a fluid system within a formation and is a substantial factor in the development of efficient oil recovery protocols and production management. IFT is strongly influenced by temperature, pressure, and oil composition, and it is therefore important to determine the IFT of "live" oil - oil under reservoir conditions. While potentially useful in the design of wellbore operations, live oil IFT is rarely, if ever, used in practice because there are no known techniques to measure the IFT of a live oil downhole, and laboratory measurements require the acquisition of sample downhole and transport to a pressure- volume-temperature (PVT) laboratory under controlled conditions. Sample isolation and transport contribute to added time and material costs, and common practice is often to use the results from "dead" oil - oil under standard temperature and pressure - instead.
  • PVT pressure- volume-temperature
  • dead oil measurements may introduce uncertainty because dead oil is often no longer representative of the live oil once collected at the surface, because the oil has undergone significant changes depending on how the sample transitioned from reservoir to surface conditions. Changes in dead oil composition and chemistry that may occur include reductions in gas and volatile content, changes in density, changes in surfactant concentration, and the like, all of which can affect the resulting IFT.
  • IFT is proportional to the density difference between immiscible fluids in contact, such as oil and water, and reciprocally proportional to interface width, which depends strongly on temperature and surfactant concentration.
  • temperature decreases (under isobaric conditions) the IFT is affected by two phenomena. Dissimilarity in the thermal expansion factor for oil and water results in IFT decrease, whereas reduction of thermal smearing of the oil/water boundary causes IFT increase. Based on varying thermodynamic properties for different oils, either of these effects can predominate. Below the saturation pressure, decrease in pressure (under isothermal conditions) corresponds to IFT decrease, because gas release causes an increase of the oil density and surfactant concentration.
  • methods in accordance with the present disclosure may be used to derive a reconstructed live oil IFT value using measurements performed on dead oil.
  • Reconstructed IFT may be used in a number of planning processes, such as incorporation into a reservoir simulator.
  • IFT is one factor used to describe the moving fluids within the systems, and may be used to estimate oil and water displacement at reservoir temperatures and pressures, including anticipating water cut and the composition of produced fluids.
  • IFT can change over time and/or in neighboring wells, and may be used in some embodiments to predict production quality changes.
  • IFT values may be updated during production based on the amount and composition of the output, particularly over time as the levels of hydrocarbon in the reservoir deplete.
  • methods in accordance the present disclosure may include generating a workflow for reconstruction of live oil interfacial tension (IFT) at reservoir conditions from IFT measurements performed on dead oil samples.
  • a correction factor may be applied to IFT obtained from dead oil to calculate an IFT for any given set of temperature and pressure values, and for varying oil and chemical compositions. Correction factors may be determined from empirical relationships between dead oil measurements, knowledge of depletion path-dependent compositional changes, and corresponding live oil composition measurements obtained from downhole measurements, such as PVT measurements.
  • the methods may include developing a database of IFT measurements to populate the thermodynamic pathways from a live oil sample at reservoir conditions to a dead crude oil.
  • Eq. 1 A is the mixing energy parameter, z is direction perpendicular to the interface and p is defined by Eq. 2, where 3 ⁇ 4 and p 0 is density of brine and oil respectively, z in t the position of the dividing interface, and ⁇ is the characteristic thickness of the interface.
  • the thickness of the interface ⁇ depends on temperature and surfactant concentration, while the fluid densities are dependent on temperature, pressure, and fluid composition (the amount of gas dissolved in the fluid).
  • Eq. 1 can be rewritten as Eq. 3.
  • Eq. 3 may be used to reconstruct IFT at reservoir conditions given fluid phase density, interface thickness, and mixing energy parameter for the fluids.
  • a correction factor may be obtained to convert a dead oil IFT measurement into an IFT that corresponds to a live oil measurement.
  • the crude oil thermodynamic pathway may be rationalized as a sequence of isothermal (depressurization at constant temperature) and isobaric (cooling under constant pressure) transformations, and IFT evolution may be quantified with consideration to a number of governing phenomena.
  • Governing phenomena that contribute to changes in IFT include changes in fluid density associated with the release of gas from a fluid system below saturation pressure, such as in response to a decrease in pressure under isothermal conditions.
  • IFT density changes occur upon the evolution of volatile or "light" components from a fluid system, which also leads to a decrease in the oil-brine density difference and an increase in the surfactant concentration. If the temperature is decreased under isobaric conditions, the IFT is affected by two phenomena having opposing impacts on IFT. On one hand, IFT decreases as the oil-brine density difference decreases, while the IFT increases as the thermal smearing of the oil/brine boundary, associated with the interface thickness ⁇ , is reduced. The overall change in IFT depends in part on crude oil composition and temperature interval, as either factor may govern within different temperature intervals.
  • FIG. 1 a phase diagram for a crude oil sample is shown with two pathways from live to dead stages.
  • the "depletion pathway” from live crude to dead crude consists of one isotherm and one isobar shown as Path 1 or Path 2 in FIG. 1.
  • a "depletion pathway” often does not coincide with either of these paths.
  • FIG. 2 a phase diagram showing an example of decomposition of an actual depletion path (solid black line) is shown divided into a sequence of isotherms ( ⁇ ) and isobars ( ⁇ ) and two limiting paths shown as dashed lines.
  • Limiting path 1 is shown as a single isobar and single isotherm
  • limiting path 2 is shown as a single isotherm and single isobar.
  • Deviation of reconstructed IFT from the true IFT value may grow with coarse graining of isobars and isotherms and reaches a maximum for Limiting paths 1 and 2. As the result, restoration of the live oil IFT value along these limiting paths will give the borders of the interval within which the true IFT value is located.
  • the depletion path may also be defined by an operator or by algorithm based on knowledge of formation conditions to improve accuracy. Further, samples of live fluids may be used to determine the IFT along points of a selected depletion path in some embodiments.
  • methods in accordance with the present disclosure are directed to a workflow, designed to gather information about the thermodynamic dependencies of interfacial tension of a downhole fluid composition at various environmental conditions.
  • a workflow in accordance with the present disclosure to establish an estimation of live crude oil IFT from dead oil measurements is shown.
  • methods may begin at 302 by obtaining a sample of dead oil and performing an IFT measurement at standard temperature and pressure.
  • the ratio of the gas volume leaving the fluid system to the volume of oil at standard conditions i.e., the gas to oil ratio, gas:oil ratio, or GOR
  • the IFT correction factor is derived from the estimation of live oil density at reservoir conditions, the interface thickness ⁇ at reservoir conditions, and mixing energy parameter value A. All these parameters are then used in Eq.3 to get the IFT.
  • the live oil density may be estimated based on GOR by taking into account the amount and composition of gas released from the oil during depletion.
  • Downhole measurements may include the output of a downhole fluid analyzer (DFA), flash analysis (single or multistage) using an onsite separator, or through PVT laboratory analysis using downhole sample.
  • DFA downhole fluid analyzer
  • flash analysis single or multistage
  • PVT laboratory analysis using downhole sample
  • the density for a corresponding live oil sample is then calculated at 306 using known empirical relationships and data obtained from onsite PVT analysis, laboratory analysis or live oil samples, downhole analysis, or using equation of state calculations.
  • Other techniques capable of determining live oil density may be used without exceeding the scope of the instant disclosure.
  • a correction factor may be determined to convert the dead oil measurement to a corresponding live oil measurement.
  • a correction factor and/or live oil IFT may be established through empirical relationships determined by lab experiments, such as presented in Eq. 3 at 308.
  • testing for various oil compositions under assorted temperature and pressure conditions, including assays studying possible depletion paths, may be compiled into a database and consulted in a manual or automated process to attain a correction factor for subsequent IFT measurements. Results from the database may be applied to dead oil IFT as a correction factor in some embodiments, or as a correlation based on GOR and density in other embodiments.
  • An adjusted IFT corresponding to a live oil measurement within the selected interval of a wellbore may then be calculated at 310 using the calculated correction factor.
  • an IFT correction factor may be obtained to estimate IFT of live oil at reservoir conditions, or at any point along the depletion path at a given pressure and temperature.
  • IFT may be corrected for changes in oil composition and density resulting from, for example, light component and volatiles removal, change in the concentration of various chemical components such as asphaltenes using initial chemical composition determinations from PVT logs.
  • heavy oils (those having lower API gravity) may have lower capacity to contain dissolved gas than lighter oils, and IFT may vary less over a given temperature and pressure range.
  • Chemical composition gradients may also exist within and between adjacent wells, creating changes in measured IFT.
  • Embodiments of the present disclosure may be implemented on a computing system. Any combination of mobile, desktop, server, embedded, or other types of hardware may be used.
  • the computing system (400) may include one or more computer processor(s) (402), associated memory (404) (e.g., random access memory (RAM), cache memory, flash memory, etc.), one or more storage device(s) (406) (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory stick, etc.), and numerous other elements and functionalities.
  • the computer processor(s) (402) may be an integrated circuit for processing instructions.
  • the computer processor(s) may be one or more cores, or micro-cores of a processor.
  • the computing system (400) may also include one or more input device(s) (410), such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device.
  • the computing system (400) may include one or more output device(s) (408), such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device.
  • a screen e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device
  • a printer external storage, or any other output device.
  • One or more of the output device(s) may be the same or different from the input device(s).
  • the computing system (400) may be connected to a network (412) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) via a network interface connection (not shown).
  • the input and output device(s) may be locally or remotely (e.g., via the network (412)) connected to the computer processor(s) (402), memory (404), and storage device(s) (406).
  • LAN local area network
  • WAN wide area network
  • the input and output device(s) may be locally or remotely (e.g., via the network (412)) connected to the computer processor(s) (402), memory (404), and storage device(s) (406).
  • Software instructions in the form of computer readable program code to perform embodiments of the invention may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium.
  • the software instructions may correspond to computer readable program code that when executed by a processor(s), is configured to perform embodiments of the invention.
  • one or more elements of the aforementioned computing system (400) may be located at a remote location and connected to the other elements over a network (412). Further, embodiments of the invention may be implemented on a distributed system having a plurality of nodes, where each portion of the invention may be located on a different node within the distributed system.
  • the node corresponds to a distinct computing device.
  • the node may correspond to a computer processor with associated physical memory.
  • the node may alternatively correspond to a computer processor or micro-core of a computer processor with shared memory and/or resources.

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Abstract

L'invention concerne des procédés pouvant comprendre la mesure d'une tension interfaciale (IFT) pour un échantillon d'huile morte préparé à partir d'un fluide à l'intérieur d'un intervalle d'une formation ; le calcul d'un rapport gaz/huile pour le fluide à l'intérieur de l'intervalle d'une formation à une température et une pression spécifiées ; le calcul d'une densité d'huile brute pour le fluide à l'intérieur de l'intervalle d'une formation pour la température et la pression spécifiées ; et la conversion de l'IFT pour l'échantillon d'huile morte en une mesure d'IFT corrigée pour une huile brute à l'intérieur de l'intervalle de la formation à partir du rapport gaz/huile calculé et de la densité calculée. Les procédés peuvent également comprendre la construction d'un trajet d'appauvrissement pour l'échantillon d'huile morte provenant d'un ou plusieurs isobares et d'un ou plusieurs isothermes ; et la conversion de l'IFT pour l'échantillon d'huile morte en une mesure d'IFT corrigée à partir du rapport gaz/huile calculé et de la densité d'huile brute calculée pour une huile brute.
PCT/US2017/062758 2016-12-02 2017-11-21 Procédé de prédiction de tension interfaciale d'huile brute dans des conditions de réservoir à partir de mesures d'huile morte Ceased WO2018102199A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US15/367,635 2016-12-02
US15/367,635 US10613251B2 (en) 2016-12-02 2016-12-02 Method for prediction of live oil interfacial tension at reservoir conditions from dead oil measurements

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ES2745339B2 (es) * 2018-08-28 2021-08-31 Univ Santiago Compostela Método para determinar la tensión interfacial
CN113536201B (zh) * 2020-04-21 2023-09-26 中国石油天然气股份有限公司 凝析气藏天然气体积系数确定方法及装置

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US20110112815A1 (en) * 2009-11-11 2011-05-12 Schlumberger Technology Corporation Method of selecting additives for oil recovery
US20150330962A1 (en) * 2014-05-14 2015-11-19 Instituto Mexicano Del Petroleo Measurement process of minimum miscibility pressure (mmp) and critical points of a gas in crude oils or binary mixtures
US20160024372A1 (en) * 2014-10-30 2016-01-28 Chevron U.S.A. Inc. Subterranean producing zone treatment

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US10613251B2 (en) 2020-04-07

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